The present invention relates to a process of stimulating oil recovery from subterranean reservoirs or formations utilizing injection of gases. It is more specifically concerned with improving he efficiency of a secondary oil recovery process wherein carbon dioxide is used as a viscosity-reducing agent.
Significant quantities of low gravity crude oil exist in underground formations. Because of this, techniques have been developed for stimulating production of oil from such reservoirs the high viscosity of the oil remaining in such formations makes recovery difficult and expensive. A number of methods designed to stimulate recovery of high viscosity petroleum have been used, including water flooding, steam injection, and gas injection, but none to date has been totally satisfactory. Typically, water flooding is inefficient for displacing viscous oil due to its high viscosity. Steam injection lowers viscosity, but is also unsatisfactory in certain types of formations and requires availability of inexpensive fuel and a large supply of clean water. A recent variation of the "huff and puff" steam injection method for reducing the viscosity of viscous oil is disclosed by West in U.S. Pat. No. 3,782,470. In "huff and puff" steam injection, the well is used for alternate injection of steam and production of reservoir fluids. In the recent variation, immediately following the injection phase of a "huff and puff" steam stimulation process, which lowers viscosity of the oil, a non-condensing, non-oxidizing gas is injected at ambient temperature. The gas displaces the low viscosity oil and thereby improves oil production rates, reduces the volume of steam required, and improves the water-oil ratio of the well. However, where a multi-component gas is employed, such as natural gas, the higher molecular weight hydrocarbons tend to condense as the formation cools following steam injections. The condensed hydrocarbons have high solubility and even miscibility with most crudes. As a result, crude oil may be miscibly displaced from the vicinity of the wellbore, resulting in reduced permeability to oil at the well bore.
Many types of chemical additives have also been evaluated to enhance the flow of viscous oil, such as surfactants and soluble oils. A solvent may be used to effectively reduce the viscosity of the oil, but unless the solvent remains soluble, it will usually be produced preferentially to the oils as an immiscible, mobile phase. One of the most successful solvents used to stimulate recovery of viscous oils is carbon dioxide. The high solution factor of carbon dioxide in crude oil causes the viscosity of the carbon dioxide-crude oil solution to be markedly lower than that of the crude alone. For illustrative examples of stimulation processes utilizing carbon dioxide, reference is made to U.S. Pat. No. 3,442,332, which incorporates a list of U.S. patents and publications on the subject at column 2, lines 24 through 49.
In oil recovery, two general types of processes utilizing carbon dioxide, typically in a gaseous form, are common. Where direct communication between adjacent wells exists or can be established, carbon dioxide may be introduced into the formation by one or more injection wells and the solution of crude oil and carbon dioxide withdrawn through one or more production wells. A second method uses the "huff and puff" technique employing the same well for alternate injection and production. This latter method is useful where communication between wells has not been established. Usually, carbon dioxide is introduced into the well, the formation is closed off to allow absorption of the carbon dioxide, and the resulting carbon dioxide-crude oil solution expands to fill the void spaces of the reservoir. The expanded solution will spontaneously flow or can be pumped to the surface once the well is reopened.
In U.S. Pat. No. 4,390,068, an improvement upon these methods of using carbon dioxide to stimulate oil production results from introducing the solvent into the formulation as a liquid under a back pressure as low as about 300 p.s.i.g. Liquid carbon dioxide can be placed into the formation at about twice the mass rate of gas injection and is believed also to be more effective than gaseous carbon dioxide for displacing unwanted water saturation associated with the residual crude oil. As a result, oil recovery increases while water recovery decreases. In addition, maintaining the back pressure at no more than 300 p.s.i.g. displaces little oil from the wellbore. Resaturating the area of displaced oil surrounding the wellbore before production can begin is therefore not required.
It has long been known that recovery of petroleum using carbon dioxide could be greatly increased if the carbon dioxide were used in slug form and driven through the reservoir by an aqueous drive fluid, such as saline, plain, or carbonated water. A process using this technique is disclosed by Holm in U.S. Pat. No.3,065,790. However even alternate-injection, water-solvent processes using carbon dioxide as a solvent succeed in recovering only the petroleum in the reservoir contacted by the injected carbon dioxide. Large quantities of uncontacted petroleum are by-passed and left in the reservoir because an unfavorable mobility relationship between reservoir fluids and injected fluids causes the carbon dioxide to channel off into areas of high permeability. In the art of oil recovery, the areal sweep efficiency of oil displacement is greatest when the viscosity of the displacing fluid is equal to or greater than the viscosity of the displaced oil and/or the permeability of the displacing fluid is less than or equal to that of the oil. Since carbon dioxide is less viscous and more mobile than most crude oils, it is not of itself a very efficient oil displacement agent.
The areal sweep efficiency of carbon-dioxide recovery is increased by generating a foam in situ to block the highly permeable features of the underground formation. U.S. Pat. No. 3,342,256 to Bernard et al. (which is hereby incorporated by reference in its entirety) discloses alternative methods for generating foam in situ to prevent channeling of carbon dioxide into high permeability channels away from the zone to be treated. In one embodiment, a small amount of a surfactant or foaming agent is dissolved in the carbon dioxide, which is maintained as a dense fluid or liquid at pressures in excess of about 700 p.s.i.g. to ensure solubility. A subsequently injected drive medium, such as water, forces the carbon dioxide-surfactant mixture through the formation to a production well where production continues until the produced fluids exhibit an undesirably high water/oil ratio. Production is then terminated, and the formation is depressurized to allow dissolved gases to come out of solution and form the foam. As the foam expands, it drives additional oil towards the producing well.
In an alternative embodiment, alternate slugs of the foaming agent, usually dissolved in an aqueous or hydrocarbon vehicle, and the carbon dioxide are introduced into the reservoir. When a hydrocarbon vehicle is employed, the liquid light hydrocarbons will flash, producing a gas to generate foam in the areas of the reservoir of high pressure gradient, such as is found in high permeability channels. If a carbonated water vehicle is used to dissolve the foaming agent, upon encountering such areas of reduced pressure, the carbon dioxide will come out of solution and generate foam. The foam generated in situ by these released gases blocks the highly permeable strata and will prevent subsequently injected slugs of carbon dioxide from channeling into highly permeable zones.
Relying upon gases released in low pressure zones to generate the foam, however, presents certain disadvantages. When the foaming agent is dissolved directly into carbon dioxide or into carbonated water, a large portion of the gaseous carbon dioxide released in the low pressure zone does not go to generating foam, but is preferentially absorbed into the crude. And if the released carbon dioxide migrates into a high pressure region, solubility of carbon dioxide is increased and may approach miscibility at pressures in excess of about 700 p.s.i.g. These difficulties are not encountered if the foaming agent is dissolved in a hydrocarbon vehicle, but the cost of liquid hydrocarbons is generally prohibitive. Moreover, a hydrocarbon-soluble surface-active agent generally foams the oil and restricts its movement through the reservoir. The upshot is that increasing the areal sweep efficiency of the recovery method by generating foam in situ is much more difficult and expensive in the reservoir than laboratory results might otherwise indicate.
Accordingly, while each of the foregoing methods has met with some success, the need exists for further developments in enhanced oil recovery. For example, a need exists for an improved method of blocking the highly permeable zones of producing formations during carbon dioxide flooding so that the solvent is not lost into the highly permeable, relatively oil-free zones but contacts a larger cross-section of the oil-bearing strata. What is particularly needed is a method for injecting gaseous carbon dioxide in conjunction with an aqueous solution of surface active agent and a noncondensible, crude-oil insoluble gas. The insoluble, noncondensible gas will neither dissolve in the oil in place nor condense to a liquid, but remains free to generate foam of the aqueous solution in the highly permeable features of the formation. The foam generated in situ by this process will block the highly permeable zones and divert subsequently injected solvent into the less permeable, oil-containing zones, thereby substantially increasing the efficiency of oil recovery.